Heavy oil extracted by existing commercially proven in-situ production techniques such as Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) are known to have very high operating expenditures (OPEX); significant emissions (CO2, SOx, NOx, and particulate matter) and water consumption per barrel of crude produced; as well as the highest capital expenditure (CAPEX) per flowing barrel of capacity than all other oil and gas production in the world.
Moreover, a barrel of heavy oil is sold at a substantial discount to the benchmark conventional crude oils such as Brent and West Texas Intermediate as there is a great deal of upgrading required to bring heavy oil up to the quality of these conventional crudes. The qualities of bitumen that reduce its market value are: low API (Association of Petroleum Institute) gravity, high TAN (total acid number), high carbon residue, high sulphur content and high metals content (e.g. vanadium and nickel). The aforementioned parameters make the production of heavy oil marginally economical at average long term crude prices while leaving a legacy of ecological damage for future generations.
OPEX are generally divided into fixed and variable costs. Fixed OPEX includes O&M (Operations and Maintenance). Variable OPEX include the costs of fuel gas, diluent, electrical power, chemicals, catalysts, consumables, royalties and taxes. Fuel gas is consumed to raise steam in a steam plant. The steam is injected into the reservoir, heating the reservoir to enable the bitumen viscosity to be lowered such that it can be mobilized and pumped to the surface (i.e. produced). Electrical power is consumed by motor drivers for the sophisticated systems of pumps, combustion air blowers, aerial coolers, and compressors.
World economic growth and depleting conventional oil reserves has resulted in the need for heavy oil and other high cost hydrocarbon resources to be extracted to meet the growing demand. The current in-situ and mining processes for bitumen are energy intensive in terms of their requirements for steam and power and, unfortunately, produce more emissions (e.g. CO2, NOx, SOx, particulates) than any other production technique.
Diluents
Still further, heavy oil will not separate efficiently at production temperatures using Stokes law, as its specific gravity is generally too close to that of the produced water. As the viscosity and pour points of heavy oil at ambient temperatures makes it difficult to transport, light diluents, such as synthetic crude oil, naphtha and natural gas condensates, are required to blend with the oil to improve viscosity, pour point and API specific gravity, thereby facilitating the separation of the oil from the produced water and enabling its transport to upgraders/refiners.
The cost of diluents is affected by losses realized in the separation process and overall blended volume shrinkage as well as transportation costs incurred in transporting the purchased diluent to site and then transporting it back with the bitumen to the upgrader/refinery.
Natural Gas
Historically, low cost natural gas has been used as the primary energy source for bitumen recovery. The ever increasing consumption of natural gas by the rapidly developing Oil Sands in-situ and mining projects will put enough demand on the supply of natural gas to substantially increase the price for all who rely on its use. Natural gas has the lowest CO2, NOx and SOx emissions per unit of energy released than all other fossil fuels with the exception of pure hydrogen. Natural gas does not require expensive boilers, NOx reduction, flue gas desulphurization and particulate matter emissions reduction equipment. This makes natural gas the preferred fuel choice for decentralized energy consumption such as residential/commercial heating, transportation and peak power production in combined cycle plants that rely on low cost facilities/equipment. In other words, while a highly effective fuel source for bitumen recovery, natural gas is a non-ideal and expensive method for the task of simply raising heat to mobilize bitumen.
Alternative Fuels
As a result, there has been a desire to use alternative fuels. However, the use of alternative fuels such as coal, bitumen, petcoke, vacuum residuals and asphaltenes to reduce OPEX is impeded by the substantial CAPEX increase to install technologies such as gasification and drum boilers (e.g. circulating fluidized beds and direct fired boilers). The use of alternative dirty fuels also requires emission reduction equipment (e.g. selective catalytic reduction and selective non-catalytic reduction of NOx, low NOx burners or flue gas recirculation to limit the formation of NOx; flue gas desulfurization to remove SOx; and electrostatic precipitation or filtration of particulate matter). Still further, present and anticipated regulations on carbon dioxide emissions will result in the necessary capture and sequestration of carbon dioxide.
Water Consumption
Existing in-situ and mining techniques used to extract heavy oil also consume significant amounts of fresh surface and fresh/brackish deep well water per barrel of production. The production facilities generally reject water contaminated with concentrated total dissolved solids (TDS) and total suspended solids (TSS) from the production process as the additional OPEX and CAPEX makes treating this water for reuse is commercially unfeasible. This results in the accumulation of large quantities of polluted tailing pond water, typically containing 500 ppm of more of toxic water soluble hydrocarbons, with long term ecological consequences.
Zero liquids discharge through evaporation and crystallization is technically proven but is both CAPEX and OPEX intensive. There is also a great deal of water consumed in the reservoir through reservoir losses (i.e. thief zones), voidage replacement (voids created when oil is produced from the reservoir) and from boiler water blowdown. In the event that lower cost alternative fuels are used, significant increases in water consumption are likely regardless of the techniques used for fuel combustion. Atomization or emulsification of liquid fuels utilizes additional water that becomes steam that is lost through the flue gas. The flue gas desulphurization (FGD) and electrostatic precipitation (ESP) required with alternative fuels requires water, which is also lost in the flue gas itself, or by way of blowdown from the FGD and ESP systems.
Capital Expenditures
The CAPEX involved in in-situ production facilities per barrel of oil is substantially higher than other conventional oil production facilities. The total CAPEX of in-situ production facilities requires a large initial CAPEX followed by sustaining CAPEX. The initial CAPEX has the most dramatic impact on the rate of return for a project as expenditures on the field, central plant, and infrastructure facilities start years prior to the production of the first barrel of oil. The sustaining CAPEX is required throughout the life of an Oil Sands development to maintain production levels at the nameplate (i.e. design throughput) of the production facility. The sustaining CAPEX includes additional drilling and completions of steam injection and production wells, along with the necessary surface facilities (well pads and pump stations) and pipelines (steam, emulsion, vapour and lift gas) to tie the additional production into the existing central production facilities (CPF). At the CPF, where the majority of the initial CAPEX is expended, there are additional facilities in comparison to conventional oil production. The facilities that are installed include the various vessels, tanks, heat exchangers, pumps, compressors and steam generators to:
separate gas/vapour, produced water and bitumen returned from field production; treat the produced water to produce BFW (boiler feed water);
heat integration with production fluids and gases coming back from the field; generate steam using the BFW; and
capture, compress, purify, dehydrate carbon dioxide and transport it for use in enhance oil/gas recovery or disposal by sequestration (Carbon capture and Storage).
Diluents, as mentioned above, are required for bitumen separation and dehydration for pipeline transportation to the upgrader/refinery. The “bottom of the barrel” of heavy oil (defined by highest boiling points on distillation curve and molecular weights) of bitumen is predominately asphaltene and resins, of which a portion thereof ends up as a low value stream of upgrader/refinery bottoms. Partial upstream physical separation and upgrading of the bitumen in the field substantially closes the discount margin between the upgraded bitumen and the conventional oil price benchmarks. As a result, the upgrading of the bitumen and separation from the upgrader bottoms results in sales which can be transported with a substantial decrease in the amount of diluent required for blending (potentially negating the requirement of diluent altogether with a highly upgraded crude). The asphaltenes and resins contribute greatly to the low API gravity, high TAN (total acid number), high carbon residue, high sulphur content and high metals content (vanadium and nickel) of the overall bitumen barrel. By removing the asphaltene and resins, the remaining sales oil quality will have been substantially improved. The physical separation or upgrader bottoms can then be used as an alternative fuel to natural gas due its low cost and on site availability. There are several proven physical separation technologies such as solvent deasphalting, atmospheric/vacuum distillation; upgrading technologies such as delayed coking visbreaking and hydrotreating as well as many other new technology initiatives intended to create upstream partial upgrading solutions for the in-situ and mining operations.
Known systems partially address some of the aforementioned problems. For example, US Patent Application No. 2006/0243448 (now issued to U.S. Pat. No. 7,341,102) describes a flue gas injection system for heavy oil recovery. The basic concept of this system is a variation of a well studied oxyfuel concept where the flue gas that is not re-circulated back to the inlet of the boiler is treated and then compressed for use in enhanced gas recovery. The recirculation of flue gas to the inlet of the boiler is required to dilute oxygen that is separated in an air separation unit and then injected into the boiler. This allows a flue gas stream which has a higher volume percentage of CO2 relative to that of a boiler using normal combustion air. The heating of boiler feedwater to make steam is done indirectly in a conventional drum boiler or oilfield OTSGs (once through steam generator). The products of combustion (flue gas) and the steam are separate streams, with different temperatures and pressure with a separate set of different processes that lead to the streams going to potentially separate reservoirs by different reservoir completions.
U.S. Pat. No. 4,498,542 describes a direct contact low emission steam generating system and method utilizing a compact, multi-fuel burner. This system directly contacts the products of combustion with boiler feedwater. The saturated gas is used for thermal stimulation of petroleum wells through the injection of high pressure steam and combustion gas mixtures. The system makes use of three stages including: 1) combustion of fuel and oxidant air; 2) mixing with a boiler feedwater; and 3) separation of the water from the steam and combustion gases to form a 50% non-condensable combustion gas and 50% steam by mass. This system, by using oxidizing air in lieu of oxygen produced from an air separation unit, results in a significant increase in the amount of non-condensables in the high pressure steam and combustion gas mixtures. Moreover, this system describes boiler feedwater passing into the direct fired steam generator to either the petroleum well as steam or contaminated carry over water that leaves the system to an unknown location. The boiler feedwater comes from an unknown source.
U.S. Pat. No. 4,546,829 describes an enhanced oil recovery process wherein high pressure combustion products are generated that are used for indirect heating of boiler feedwater for the purposes of making steam for downhole injection or for utility use. The high pressure combustion products can then be cleaned of solids, treated, cooled and stripped of CO2 prior to downhole injection. Separate streams of nitrogen, CO2, and steam are generated separately for selective mixing prior to introduction at the petroleum reservoir. This system, by using oxidizing air in lieu of oxygen produced from an air separation unit, results in a significant increase in the amount of non-condensables to steam generated.
PCT patent application No. WO2008097666 (“Hot Fluid Recovery of Heavy Oil with Steam and Carbon Dioxide”), describes an enhanced method of heavy oil recovery through use of wet combustion and a combination of products of combustion and steam generated through direct addition of treated water or steam to a flue gas. CO2, superheated steam and combustion gases are all injected into a hydrocarbon formation. The combustor and the steam generator are combined into one chamber, and the method allows for high temperature oxy-combustion and simultaneous injection of steam and CO2, However, the single chamber combustor limits the method's ability to segregate undesirable gases, solids and other products from entering the extraction step which has the potential to interfere with the extraction process or damage the pipes or hydrocarbon-containing formation (e.g. acid corrosion of piping from sulphuric/sulphurous acid. There is no provision for capture of sulfur and other acid forming gases through direct contact of the combustion products with water in order to remove them from the system as a solid, nor is there provision for recirculation of untreated produced water for further generation of steam. This is also no provision for the removal of solids from the walls of the combustor/steam chamber with a liquid stream which would tend to cause clogging or performance changes in the system. This may restrict the method from the use of many alternative fuels, especially those containing substantial quantities of inorganic solids.
US patent application No. 20070202452 (“Direct Combustion Steam Generator”), describes a method of spiraling vortex fluid addition of combustion gases generated in a spiral chamber to water in order to generate steam, and use of oxygen in the combustion process. However, the method does not provide for use of produced water for steam generation, nor does it discuss the injection of combustion gases along with steam into a hydrocarbon containing matrix or reservoir or the separation and capture of pressurized carbon dioxide after interaction with the hydrocarbons. The method is limited to gaseous and liquid fuels because there is no means to handle the solids.
Methods and systems to overcome the afore-mentioned problems with the prior art are required for the economic production of heavy oil from oil sand with reduced environmental impact.
Industry Trends
Important industry trends are developing as a result of government regulations for the reduction of green house gas emissions through carbon dioxide capture and sequestration. Future trends will be to reduce CAPEX and OPEX of these heavy oil facilities when market forces bring lower oil prices and thus lower rates of return. In areas where there is a high density of mining and in-situ production facilities, water has become a scarce resource and thus has drawn national and world media attention. Special interest groups have and will continue to lobby government/regulatory agencies to stem further development of production facilities in those areas where water is not available or its use for heavy oil production will result in environmental damage.
There are concerns by industry, governments and special interest groups that the use of the valuable more environmentally friendly natural gas in heavy oil production is not in the best interest of the environment and the consumer.
As a result of the foregoing problems, there has been a need for a system and method that improves the operational and capital expenditure efficiency in the recovery of bitumen that is environmentally an improvement over past methodologies. In other words, there has been a need for a system that has both the positive commercial (lower CAPEX and OPEX) and regulatory (provides lower emissions) attributes and promotes its initial implementation and eventual proliferation throughout the industry. The proliferation would be in application for new and existing facilities. Potentially, the OPEX savings could warrant the replacement of existing higher OPEX steam and water treatment plant technologies especially in a carbon constrained environment.
Methods and systems to overcome the afore-mentioned problems are therefore required to enable more economic production of heavy oil with minimal environmental impact.